1. Field of the Disclosure
The present disclosure is related to the field of apparatus design in the field of oil exploration. In particular, the present disclosure describes a method for calibrating multicomponent logging devices used for detecting the presence of oil in boreholes penetrating a geological formation.
2. Description of the Related Art
Electromagnetic induction resistivity well logging instruments are well known in the art. Electromagnetic induction resistivity well logging instruments are used to determine the electrical conductivity, and its converse, resistivity, of earth formations penetrated by a borehole. Formation conductivity has been determined based on results of measuring the magnetic field of eddy currents that the instrument induces in the formation adjoining the borehole. The electrical conductivity is used for, among other reasons, inferring the fluid content of the earth formations. Typically, lower conductivity (higher resistivity) is associated with hydrocarbon-bearing earth formations. The physical principles of electromagnetic induction well logging are well described, for example, in, J. H. Moran and K. S. Kunz, Basic Theory of Induction Logging and Application to Study of Two-Antenna Sondes, Geophysics, vol. 27, No. 6, part 1, pp. 829-858, Society of Exploration Geophysicists, December 1962. Many improvements and modifications to electromagnetic induction resistivity instruments described in the Moran and Kunz reference, supra, have been devised, some of which are described, for example, in U.S. Pat. No. 4,837,517 to Barber, in U.S. Pat. No. 5,157,605 to Chandler et al., and in U.S. Pat. No. 5,600,246 to Fanini et al.
The conventional geophysical induction resistivity well logging tool is a probe suitable for lowering into the borehole and it comprises a sensor section containing a transmitter and receiver and other, primarily electrical, equipment for measuring data to infer the physical parameters that characterize the formation. The sensor section, or mandrel, comprises induction transmitters and receivers positioned along the instrument axis, arranged in the order according to particular instrument or tool specifications and oriented parallel with the borehole axis. The electrical equipment generates an electrical voltage to be further applied to a transmitter induction antenna, conditions signals coming from receiver induction antennas, processes the acquired information, stores or by means of telemetry sending the data to the earth surface through a wire line cable used to lower the tool into the borehole.
In general, when using a conventional induction logging tool with transmitters and receivers (induction antennas) oriented only along the borehole axis, the hydrocarbon-bearing zones are difficult to detect when they occur in multi-layered or laminated reservoirs. These reservoirs usually consist of thin alternating layers of shale and sand and, oftentimes, the layers are so thin that due to the insufficient resolution of the conventional logging tool they cannot be detected individually. In this case the average conductivity of the formation is evaluated.
Conventional induction well logging techniques employ antennas wound on an insulating mandrel. One or more transmitter antennas are energized by an alternating current. The oscillating magnetic field produced by this arrangement results in the induction of currents in the formations which are nearly proportional to the conductivity of the formations. These currents, in turn, contribute to the voltage induced in one or more receiver antennas. By selecting only the voltage component which is in phase with the transmitter current, a signal is obtained that is approximately proportional to the formation conductivity. In conventional induction logging apparatus, the basic transmitter antenna and receiver antenna has axes which are aligned with the longitudinal axis of the well logging device. (For simplicity of explanation, it will be assumed that the borehole axis is aligned with the axis of the logging device, and that these are both in the vertical direction. Also single antennas will subsequently be referred to without regard for focusing antennas or the like.) This arrangement tends to induce secondary current loops in the formations that are concentric with the vertically oriented transmitting and receiving antennas. The resultant conductivity measurements are indicative of the horizontal conductivity (or resistivity) of the surrounding formations. There are, however, various formations encountered in well logging which have a conductivity that is anisotropic. Anisotropy results from the manner in which formation beds were deposited by nature. For example, “uniaxial anisotropy” is characterized by a difference between the horizontal conductivity, in a plane parallel to the bedding plane, and the vertical conductivity, in a direction perpendicular to the bedding plane. When there is no bedding dip, horizontal resistivity can be considered to be in the plane perpendicular to the bore hole, and the vertical resistivity in the direction parallel to the bore hole. Conventional induction logging devices, which tend to be sensitive only to the horizontal conductivity of the formations, do not provide a measure of vertical conductivity or of anisotropy. Techniques have been developed to determine formation anisotropy. See, e.g. U.S. Pat. No. 4,302,722 to Gianzero et al. Transverse anisotropy often occurs such that variations in resistivity occur in the azimuthal direction.
Thus, in a vertical borehole, a conventional induction logging tool with transmitters and receivers (induction antennas) oriented only along the borehole axis responds to the average horizontal conductivity that combines the conductivity of both sand and shale. These average readings are usually dominated by the relatively higher conductivity of the shale layers and exhibit reduced sensitivity to the lower conductivity sand layers where hydrocarbon reserves are produced. To address this problem, loggers have turned to using transverse induction logging tools having magnetic transmitters and receivers (induction antennas) oriented transversely with respect to the tool longitudinal axis. Such instruments for transverse induction well logging has been described in PCT Patent publication WO 98/00733 of Beard et al. and U.S. Pat. No. 5,452,761 to Beard et al.; U.S. Pat. No. 5,999,883 to Gupta et al.; and U.S. Pat. No. 5,781,436 to Forgang et al.
In transverse induction logging tools, the response of transversal antenna arrays is also determined by an average conductivity; however, the relatively lower conductivity of hydrocarbon-bearing sand layers dominates in this estimation. In general, the volume of shale/sand in the formation can be determined from gamma-ray or nuclear well logging measurements. Then a combination of the conventional induction logging tool with transmitters and receivers oriented along the well axis and the transversal induction logging tool can be used for determining the conductivity of individual shale and sand layers.
One, if not the main, difficulties in interpreting the data acquired by a transversal induction logging tool is associated with vulnerability of its response to borehole conditions. Among these conditions is the presence of a conductive well fluid as well as wellbore fluid invasion effects.
In induction logging instruments, the acquired data quality depends on the formation electromagnetic parameter distribution (conductivity or resistivity) in which the tool induction receivers operate. Thus, in the ideal case, the logging tool measures magnetic signals induced by eddy currents flowing in the formation. Variations in the magnitude and phase of the eddy currents occurring in response to variations in the formation conductivity are reflected as respective variations in the output voltage of receivers. In the conventional induction instruments these receiver induction antenna voltages are conditioned and then processed using analog phase sensitive detectors or digitized by digital to analog converters and then processed with signal processing algorithms. The processing allows for determining both receiver voltage amplitude and phase with respect to the induction transmitter current or magnetic field waveform. It has been found convenient for further uphole geophysical interpretation to deliver the processed receiver signal as a vector combination of two voltage components: one being in-phase with transmitter waveform and another out-of-phase, quadrature component. Theoretically, the in-phase antenna voltage component amplitude is the more sensitive and noise-free indicator of the formation conductivity.
There are a few hardware margins and software limitations that impact a conventional transversal induction logging tool performance and result in errors appearing in the acquired data.
The general hardware problem is typically associated with an unavoidable electrical field that is irradiated by the tool induction transmitter simultaneously with the desirable magnetic field, and it happens in agreement with Maxwell's equations for the time varying field. The transmitter electrical field interacts with remaining modules of the induction logging tool and with the formation; however, this interaction does not produce any useful information. Indeed, due to the always-existing possibility for this field to be coupled directly into the receiver part of the sensor section through parasitic displacement currents, it introduces the noise. When this coupling occurs, the electrical field develops undesirable electrical potentials at the input of the receiver signal conditioning, primarily across the induction antenna receiver, and this voltage becomes an additive noise component to the signal of interest introducing a systematic error to the measurements.
The problem could become even more severe if the induction logging tool operates in wells containing water-based fluids. The water-based mud has a significantly higher electrical permittivity compared to the air or to the oil-based fluid. In the same time, the electrical impedance to the above mentioned displacement currents can be always considered as capacitive coupling between the source—the induction transmitter and the point of coupling. This circumstance apparently would result in a fact that capacitive coupling and associated systematic errors are environment dependant because capacitive impedance will be converse to the well mud permittivity.
The conventional method in reducing this capacitive coupling in the induction logging instrument lays in using special electrical (Faraday) shields wrapped around both transmitter and receiver induction antennas. These shields are electrically attached to the transmitter analog ground common point to fix their own electrical potential and to provide returns of the displacement currents back to their source—transmitter instead of coupling to any other place in the tool. However, geometry and layout effectiveness of Faraday shields becomes marginal and contradictory in the high frequency applications where conventional transverse induction tools can operate. These limitations occur due to the attenuation these shields introduce to the magnetic field known in the art as a shield “skin effect”. The shield design limitations are unavoidable and, therefore, the possibility for the coupling through displacement currents remains.
Another source of hardware errors introduced into the acquired log data is associated electrical potential difference between different tool conductive parts and, in particular, between transmitter and receiver pressure housings if these modules are spaced apart or galvanically separated. These housings cover respective electronic modules and protect them from exposure to the harsh well environment including high pressure and drilling fluids. Typically, the pressure housing has a solid electrical connection to the common point of the electronic module it covers, however, design options with “galvanically” floating housings also exist. If for some reasons, mainly imperfections in conventional induction tools, the common points of different electronic modules have an electrical potential difference between them, this difference will appear on the pressure housings. It may occur even in a design with “galvanically” floating housings if the instrument operates at the high frequencies and, in particular, through the capacitive coupling that these metal parts might have to the electronic modules encapsulated in a conductive metallic package.
Having different electrical potentials on separate pressure housings will force the electrical current to flow between them. This current would have a conductive nature and high magnitude if the induction tool is immersed in a conductive well fluid and it will be a displacement current of typically much less magnitude for tool operations in a less conductive or oil-based mud. In both cases this current is time-varying; therefore it produces an associated time varying magnetic field that is environmentally dependent and measured by the induction receiver. For those who are skilled in the art it should be understood that the undesirable influence of those currents on the log data would be significantly higher in the conventional transverse induction tool compared to the instruments having induction antennas coaxial with the tool longitudinal axis only. In particular, this is due to the commonly accepted overall design geometry of induction logging tools where transmitter and receiver sections are axially separated by the mandrel. It can be noticed that employing the induction tool in the logging string where it has mechanical and electrical connections (including telemetry) with instruments positioned both above and below could also result in the appearance of the above-mentioned currents.
Another source of the housings' potential offsets is the induction tool transmitter itself. The remaining electrical field that this transmitter irradiates simultaneously with a magnetic field could be different on the surface of separate pressure housings. Severity of this error also depends on Faraday shields' imperfections as described earlier.
There is an additional problem that the potential difference creates in conventional tool layouts having transmitter and receiver electronic modules spaced apart and using interconnection wires running throughout the sensor (mandrel) section. These wires should be electrically and magnetically shielded from induction receiver antennas in the sensor section. The entire bundle of wires is placed inside of a highly conductive metal shield that is electrically connected to the common points of separated transmitter and receiver electronic modules. This shield's thickness is selected to enable sufficient suppression of mutual crosstalk between wires and sensor section antennas within the entire operational frequency bandwidth and, primarily, at its lower end. In some cases, this shield is a hollow copper pipe, often called as a feed-though pipe, with a relatively thick wall.
However, besides protecting the sensor section transmitter and receiver antennas and interconnecting wires from mutual crosstalk, this shield simultaneously creates a galvanic path for the currents that could be driven by pressure housings and/or electronic potential difference, or induced by the induction transmitter (as discussed in U.S. Pat. No. 6,586,939 to Fanini et al, having the same assignee as the present application and the contents of which are incorporated herein by reference). This path apparently exists along the shield's external surface and for a given frequency its depth and impedance has been controlled by the shield geometry, material conductivity and magnetic permeability. The time varying currents also generate a respective magnetic field that crosses induction receiver antennas and induces error voltages. Unfortunately, these error voltages are also environmentally dependent and their changes cannot be sufficiently calibrated out during tool manufacturing. The overall analysis of the potential difference influence demonstrates that in the conductive well fluid, galvanic currents flowing through the fluid along external surface of the induction tool would dominate. The superposition and magnitude of these galvanic currents strongly depend up on the ambient temperature that pushes the conventional induction tool performance to further deterioration.
Another source of systematic errors introduced in the log data is directly determined by uncertainties in mechanical dimensions of multi-component transmitter and receiver antennas in the sensor section related both to their overall dimensions and positions with respect to each other. Thus, to keep required signal phase relationships, conventional tool designs have primarily relied on the mechanical stability and electrical properties of advanced ceramics and plastic materials to build the mandrel. However, even slight physical assembly deviations in the antenna wires position and non-uniform antenna form material temperature dependencies might destroy a factory pre-set compensation of the transmitter primary magnetic field coupled in the receiver antenna (bucking) during well logging, and create non-recoverable errors due to mechanical displacement or imperfections.
U.S. Pat. No. 6,734,675 and U.S. Pat. No. 6,586,939 to Fanini et al., both having the same assignee as the present application and the contents of which are incorporated herein by reference, address some of the issues present in the calibration and use of multicomponent induction logging tools. Fanini '939 discloses a transverse induction logging tool having a transmitter and receiver for downhole sampling of formation properties, the tool having a symmetrical shielded split-antenna transmitter antenna and a bucking antenna interposed between the split transmitter antennas to reduce coupling of the transmitter time varying magnetic field into the receiver. The tool provides symmetrical shielding of the antennas and grounding at either the transmitter or receiver end only to reduce coupling of induced currents into the received signal. The tool provides an insulator between receiver electronics and the conductive receiver housing having contact with conductive wellbore fluid, to reduce parasitic current flowing in a loop formed by the upper housing, feed through pipe, lower housing and wellbore fluid adjacent the probe housing or mandrel. An internal verification loop is provided to track changes in transmitter current in the real and quadrature component of the received data signal.
Fanini '675 discloses a transverse induction logging tool having a transmitter and receiver for downhole sampling of formation properties, the tool having a symmetrical shielded split-antenna transmitter antenna and a bucking antenna interposed between the split transmitter antennas to reduce coupling of the transmitter time varying magnetic field into the receiver. The tool provides symmetrical shielding of the antennas and grounding at either the transmitter or receiver end only to reduce coupling of induced currents into the received signal. The tool provides an insulator between receiver electronics and the conductive receiver housing having contact with conductive wellbore fluid, to reduce parasitic current flowing in a loop formed by the upper housing, feed through pipe, lower housing and wellbore fluid adjacent the probe housing or mandrel. An internal verification loop is provided to track changes in transmitter current in the real and quadrature component of the received data signal.